British Columbia borrows from Alberta’s royalty framework for energy development
On the left coast, the gas industry is greeted by a co-operative regime and light royalties adapted from B.C.’s neighbor
But if B.C. fails to make its natural gas wealth fuel a permanently healthier northern economy, it will not be for lack of trying. The summer drilling aid announcement was a relatively minor addition to an array of incentive schemes. B.C. has worked at encouraging the Alberta-based energy industry to spread across the provincial boundary since the late-1990s construction of Calgary-based Alliance Pipeline as a $5-billion export express route from Fort St. John to the North American gas trading hub at Chicago.
Provincial moves ranged from exploration incentives to road-building partnerships with companies, a “fair-share” grant program for municipalities to cope with service and infrastructure strains of industrialization, and creation of the B.C. Oil and Gas Commission as a “single-window” agency to replace a former regulatory maze. The efforts worked.
“B.C. had a bad reputation. They’ve changed right around,” says Brent Snyder, manager of Devon Canada Corp.’s B.C. shale gas development campaign. “They are really welcoming ideas, discussions and the royalty review to help us get started. Up there they’re saying, ‘Tell us what you’d like to see and we’ll accommodate you.’”
The major current initiative is implementing a B.C. gas clone of the oil sands royalty regime that Alberta enacted a dozen years ago to kick-start bitumen development. Details, including company identities, are confidential. But negotiations are understood to be underway with sponsors of up to half a dozen projects in the remote Horn River shale gas deposit between Fort Nelson and B.C.’s boundary with the Yukon and Northwest Territories.
“It’s certainly extremely important,” Lekstrom says. Like the oil sands, B.C. shale gas is a matter of using and improving expensive technology to tap a well-known resource with potential to deliver production growth for generations to come.
The policy formula is a net profit royalty. It makes big exceptions to standard provincial practices of taking shares of gross sales on sliding scales that move in step with rises or falls by output volumes and prices. The net profit regime holds royalties down to a token level when projects are new, then for the rest of their lives only applies the rates to revenues left over after deductions of agreed expenses.
B.C. shale gas royalties are two per cent of gross revenues until initial capital costs are paid off by up to 10 years of production. Then rates rise in “tiers” as projects evolve, gradually reaching 15 per cent, 20 per cent and 35 per cent of net sales revenues. Besides drilling costs, a long list of deductible items ranges from regulatory expenses such as environmental studies to air strips, roads, bridges, wages, carbon levies, fuel taxes, land reclamation, and royalties for aboriginal communities granted mineral rights by treaties.
Like Alberta’s oil sands regime, B.C.’s net profit gas royalty was devised in collaboration with industry. Lekstrom pledges to keep up the co-operation. “My job as minister is to be accessible.”
He vows to resist temptation to jack up the rates if technology and markets make the gas prize grow. “One thing we pride ourselves on is stability,” Lekstrom says. “We’ve made a commitment. Nobody is going to get blind-sided.”
B.C. recognizes “capital is mobile,” the provincial energy minister says. “Money can go anywhere. If we want to be working in the resource extraction game we have to be competitive. We’ll create an environment where companies want to invest.”
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